1. Field of the Invention
The present invention relates to a combined cycle electric power plant and more particularly to the coordinated control adapted for controlling the afterburners supplying additional heat to the gas turbine exhaust gases passing to the heat recovery steam generator and the inlet guide vane assembly for regulating the flow of air to the gas turbine and subsequently to the heat recovery steam generator.
2. State of the Prior Art
In the design of modern electric power plants, it is a significant object to achieve the greatest efficiency possible in the generation of electricity. To this end, steam generators are designed to extract heat efficiently from and to use the extracted heat to convert a fluid such as water into superheated steam at a relatively high pressure. Further, such steam generators have been incorporated into combined cycle electric power generating plants including both gas and steam turbines wherein the exhaust gases of the gas turbine are used to heat water into steam to be supplied to the steam turbine. Typically, steam generators include a water-heating or economizer tube, a high-pressure evaporator tube and finally a superheater tube, whereby water is gradually heated at increasing levels of pressure superheated steam from the superheated tube to the steam turbine. A condenser is associated with the steam turbine to receive the spent steam therefrom and for converting it into water condensate to be fed back to the steam generator.
In a combined cycle electric power plant, the steam turbine is combined with a gas turbine whereby the heated exhaust gases of the gas turbine, otherwise lost to the atmosphere, are used to heat the circulated fluid and to convert it into steam to drive the steam turbine. In this manner, a significant reduction in the fuel required to heat the steam is achieved and the heat contained in the gas turbine exhaust gases is effectively utilized. Further, an afterburner associated with the exhaust exit of the gas turbine serves to additionally heat the gas turbine exhaust gases, whereby the heat required to generate sufficient steam to meet steam turbine load requirements is provided. In particular under conditions of relatively high loads wherein the heat of the gas turbine exhaust gases is insufficient to supply the steam requirements, the afterburner is turned on to further heat the gas turbine exhaust gases.
In a combined cycle power plant as envisioned herein, it is a requirement that the associated gas turbine, steam generator and steam turbine be properly matched in order to optimize overall plant efficiency and prevent down time. With respect to such a requirement, one item that calls for special attention is the control of gas turbine exhaust flow. Generally, the gas turbine compressor operates at constant speed and compresses essentially a constant air volume. This produces a variable gas turbine exhaust flow, which varies as a function of changes in inlet conditions, e.g. pressure and temperature. Over the normal operating range, changes in the ambient pressure cause in one illustrative configuration a maximum of approximately 7% change in gas turbine exhaust gas flow, while changes in the inlet temperature from -40.degree. F. to +120.degree. F. cause an approximate 30% change in gas turbine exhaust flow.
The quantity of and the temperature of the steam delivered by the steam generator to the steam turbine are determined by the exhaust flow from the gas turbine and the amount of afterburner firing. For a constant gas turbine exhaust flow and temperature, increasing afterburner firing rate will increase both the steam flow and temperature. For a constant afterburner firing rate, increasing the gas turbine exhaust flow will increase the steam flow and decrease the steam temperature.
As the gas turbine inlet temperature decreases, the gas turbine exhaust flow increases. If the steam temperature is to be held constant, the afterburner firing rate must be increased with the resulting increase in steam flow. If the afterburner firing rate is not increased, the steam flow will increase and the steam temperature will decrease. The steam turbine is designed for a certain steam flow at a specified pressure and temperature. Since, in an illustrative embodiment of this invention, the steam turbine is designed to operate in the turbine following mode (control valves open), the steam pressure must be increased in order to increase steam flow. However, reducing steam temperature results in moisture problems in the steam turbine.
Further, it is desirable to achieve maximized efficiencies or high heat rates in the operation of such combined cycle electric generating power plants. Ordinarily, gas turbines are operated at base load because of poor heat rates at reduced load. However, in the combined cycle plant or in the case of larger gas turbines, reduced load operation of the gas turbine is often a necessity since the full generating capability of the plant or turbine is not always required. Consequently, modulating the inlet guide vanes of the gas turbine at reduced loads is undertaken in order to improve heat rate and increase the gas turbine exhaust gas temperature, which increase is then utilized to supplement the afterburner and steam generator functions.
The modulation of the inlet guide vanes of a gas turbine for differing purposes is known. For example, in the aforementioned application Ser. No. 323,593, the inlet guide vanes are positionally controlled to hold gas turbine exhaust temperature at a constant value over its operating range in order to simultaneously generate power and drive an external, unrelated process. In particular, such operation is achieved as a function of a temperature control loop and the combustor shell pressure. In U.S. Pat. No. 3,623,326, issued to C. Greune on Nov. 30, 1971, inlet guide vane modulation is utilized to maintain a constant, high exhaust gas temperature, both during acceleration and in steady-state performance of a gas turbine driven vehicle. In particular, such control is effected as a function of throttle position. Reference may also be had to commonly-assigned and co-pending application Ser. No. 319,114 and the related cases cited therein for a further example of inlet guide vane regulation as a function of speed.
None of these prior art arrangements is particularly suitable for use in a combined cycle generating plant. Neither are any of the known alternative schemes, as is perhaps exemplified by U.S. Pat. No. 3,097,486, issued to R. Roe on July 16, 1963. In the Roe patent, the entire exhaust of the gas turbine is delivered to a steam furnace for utilization therein as a function of speed or air flow control means which sense the plant power demands. Thus, as load demand on the system varies and the compressor output is regulated by speed or air flow control means, the rate of flow through the furnace is regulated such that the higher the loading, the higher the exhaust temperature of the turbine and, conversely, the lower the loading, the cooler the exhaust temperature.
In order to improve heat rates and increase the overall plant efficiency, it is necessary at lower gas turbine loading to utilize exhaust temperature as a supplemental heating source for steam generation. While the Roe patent comes closest to this, it and the other known prior art arrangements are not directed to achieving the desired result.
Also of interest is U.S. Pat. No. 2,946,187, issued on July 26, 1960 to R. Zorschak et al. While no particular inlet guide vane positioning control is disclosed therein, this patent does allude to the fact that there is a need in combined cycle power plants to respond to temperature changes at the gas turbine inlet in order to promote and improve overall plant efficiency. No particularized solution is presented herein or in any of the other noted prior art arrangements.
In the operation of a steam generator or a heat recovery steam generator as incorporated in the combined cycle electric power plant, it is particularly desirable to control within a minimum range the temperature of the superheated steam as supplied to the steam turbine, whereby the power generating efficiency of the electrical power plant is maintained at a relatively high level. In steam heaters of the prior art, there has been suggested that control of the superheated steam may be maintained by bypassing a portion of the steam derived from a steam drum of the steam generator, through a separate conduit about the superheater tube, whereby the relatively cold bypassed steam and the relatively hot superheated steam are recombined in selected proportions to achieve the desired temperature. For example, U.S. Pat. No. 1,779,706, such a steam generator is suggested whereby primary and secondary superheater tubes are provided with a bypass conduit disposed about the primary superheater. The temperature of the steam passing from the steam generator output is measured and applied to a controller whereby the flow through the bypass conduit is controlled. The noted U.S. Pat. No. 1,779,706 does not, however, disclose that such control may be incorporated into or adapted to solve the particular problems of a combined cycle electric power plant.
Further, there is known in the prior art to spray or otherwise inject condensate water as derived from the condenser associated with the steam turbine into the fluid part of the steam generator. For example, the condensate water as driven by the main feed pump may be sprayed into the steam generator at a point intermediate between a primary superheater tube and a secondary superheater tube. Thus, a valve may be selectively opened and closed to introduce the condensate water into the steam generator, whereby the temperature of the superheated steam may be correspondingly varied. In particular, the temperature of the superheated steam as derived from the steam generator and supplied to the steam turbine is measured and this variable is used to control the position of the condensate water inlet valve.
In the prior art systems where it is attempted to achieve superheated steam temperature control by solely bypassing a portion of the fluid about a heat exchange tube of the steam generator or to inject feedwater at an intermediate portion thereof, it has been found that such temperature control is relatively unstable and that wide ranges of superheated steam temperature result for a given load demand. For example, for a steady-state load demand, prior art superheated steam temperature controls are typically capable of achieving superheated steam temperatures that vary over a range of approximately 1%, whereby a corresponding deviation in the megawatt output will occur. Similarly, where the load demand signal is varying, the prior art superheater steam temperature controls are capable of maintaining regulation to only 2% with a corresponding drop in the power output.
The description of prior art herein is made on good faith, and no representation is made that any prior art considered is the best pertaining prior art or that the interpretation placed on it is unrebuttable.